1. Field of the Invention
The invention relates generally to earth-boring bits used to drill a borehole for the ultimate recovery of oil, gas, or minerals. More particularly, the invention relates to fixed cutter drill bits for directional drilling. Still more particularly, the invention relates to a fixed cutter bit including shaped cutter elements to selectively control depth of cut and bit aggressiveness.
2. Background of the Invention
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.
Many different types of drill bits and cutting structures for bits have been developed and found useful in drilling such boreholes. Two predominate types of rock bits are roller cone bits and fixed cutter (or rotary drag) bits. Many fixed cutter bit designs include a plurality of blades that project radially outward from the bit body and form flow channels there between. Typically, cutter elements are grouped and mounted on the several blades.
The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond (“PCD”) material. In the typical fixed cutter bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of one of the several blades. A cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. For convenience, as used herein, reference to “PCD bit” or “PCD cutter element” refers to a fixed cutter bit or cutter element employing a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.
While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The flowing fluid performs several important functions. The fluid removes formation cuttings from the bit's cutting structure. Otherwise, accumulation of formation materials on the cutting structure may inhibit or prevent the penetration of the cutting structure into the formation. In addition, the fluid removes cut formation materials from the bottom of the borehole. Failure to remove formation materials from the bottom of the borehole may result in subsequent passes by the cutting structure to re-cut the same materials, thus reducing cutting rate and potentially increasing wear on the cutting surfaces. The drilling fluid and cuttings removed from the bit face and from the bottom of the borehole are forced and carried to the surface through the annulus that exists between the drill string and the borehole sidewall. Still further, the drilling fluid removes frictional heat from the cutter elements in order to prolong cutter element life. Thus, the number and placement of drilling fluid nozzles, and the resulting flow of drilling fluid, may significantly impact the performance of the drill bit.
Most conventional cutter elements include a planar cutting face that presents a relatively aggressive cutting edge to the formation. Although aggressive cutter elements tend to enhance ROP, they can trigger other less desirable results in both directional and conventional drilling applications.
Depending on the location and orientation of the target formation or pay zone, directional (e.g., horizontal drilling) with the drill bit may be desired. In general, directional drilling involves deviation of the borehole from vertical (i.e., drilling a borehole in a direction other than substantially vertical), and is typically accomplished by drilling, for at least some period of time, in a direction not parallel with the bit axis. Directional drilling capabilities have improved as advancements in measurement while drilling (MWD) technologies have enabled drillers to better track the position and orientation of the wellbore. In addition, more extensive and more accurate information about the location of the target formation as a result of improved logging techniques has enhanced directional drilling capabilities. As directional drilling capabilities have improved, so have the expectations for drilling performance. For example, a driller today may target a relatively narrow, horizontal oil-bearing stratum, and may wish to maintain the borehole completely within the stratum. In some complex scenarios, highly specialized “design drilling” techniques with highly tortuous well paths having multiple directional changes of two or more bends lying in different planes may be employed.
One common method to control the drilling direction of a bit is to steer the bit using a downhole motor 6 with a bent sub 4 and/or housing. As shown in FIG. 1, a simplified version of a downhole steering system according to the prior art comprises a rig 1, a drill string 2 having a downhole motor 6 with a bent sub 4, and a conventional fixed cutter drill bit 8. Motor 6 and bent sub 4 form part of the bottomhole assembly (BHA) and are attached to the lower end of the drill string 2 adjacent the conventional drill bit 8. When not rotating, the bent sub 4 causes the bit face to be canted with respect to the tool axis. The downhole motor 6 is capable of rotating conventional drill bit 8 without the need to rotate the entire drill string 2. For example, downhole motor 6 may be a turbine, an electric motor, or a progressive cavity motor that converts drilling fluid pressure pumped down drill string 2 into rotational energy at drill bit 8. When downhole motor 6 is used with bent sub 4 without rotating drill string 2, drill bit 8 drills a borehole that is deviated in the direction of the bend or curve in the bent sub 4. On the contrary, when the drill bit is rotated by rotating the drill string, the borehole normally maintains a linear path or direction generally along the projection of the drill string longitudinal axis, even when a downhole motor is used, since the bent sub or housing rotates along with the drill string, and thus, no longer orients the drill bit in a specific direction. Consequently, a combination of a bent sub or housing and a downhole motor to rotate the drill bit without rotating the drill string generally provides a more effective means for deviating a borehole.
In most cases, directional drilling is accomplished by alternating the rotation of drill bit 8 between drill string 2 and downhole motor 6. While rotating drill bit 8 with drill string 2 and motor 6, commonly referred to as the “rotating mode,” bit 8 proceeds to form a relatively straight borehole generally aligned with the longitudinal axis of drill string 2. However, when rotating drill bit 8 with downhole motor 6 and not drill string 2, commonly referred to as the “steering mode” or “sliding mode,” the bent sub 4 causes the drill bit 8 to proceed to form a borehole oriented at an angle relative to the longitudinal axis of drill string 2. By alternating between the rotating mode and steering mode (i.e., alternating between the rotation of drill bit 8 between drill string 2 and downhole motor 6), a curved (i.e., non-linear) borehole may be formed.
Directional drilling often results in increased engagement and associated frictional forces between the low side of the drill string and the borehole sidewall. In particular, as the inclination of the well increases towards horizontal, it becomes more difficult to apply weight on bit (WOB) effectively since the borehole bottom is no longer aligned with the force of gravity—increasing bends in the drill string tend to reduce the amount of downward force applied to the string at the surface that is translated to WOB acting at the bit face. Consequently, directional drilling with a combination of a downhole motor and a bent sub may decrease the effective WOB. In addition, where the drill string is not rotating, or is rotated very little, such as during the steering mode in directional drilling applications, the rotational shear acting on the drilling fluid in the annulus between the drill string and borehole wall is decreased, as compared to a case where the entire drill string is rotating. Since drilling fluids tend to be thixotropic, the reduction or complete loss of the shearing action tends to adversely affect the ability of the drilling fluid to flush and carry away cuttings from the borehole. As a result, in deviated holes drilled with a downhole motor and bent sub, formation cuttings are more likely to settle out of the drilling fluid on the bottom or low side of the borehole. This may increase borehole drag, making weight-on-bit transmission to the bit even more difficult, and often resulting in tool face control and prediction problems. To overcome the increased frictional forces and provide sufficient effective WOB for drilling, weight applied to the drill string at the surface is steadily increased, in a process commonly referred to as “weight stacking,” until the frictional forces between the drill string and borehole sidewall are overcome. Predicting the weight at which the frictional forces will be overcome is very difficult, if not impossible. Consequently, the drill string and drill bit often unexpectedly and abruptly shift. When the drill bit suddenly advances axially into engagement with the borehole bottom under the substantial WOB, the cutter elements in the cone and shoulder regions of the drill bit penetrate the formation to a large depth-of-cut, thereby increasing the torque demands on the downhole motor. If the torque required to drill at the increased depth-of-cut exceeds the downhole motor threshold, the downhole motor may undesirably stall.
In directional and conventional drilling applications, most fixed cutter bits vibrate and/or move laterally relative to the bit axis. During such lateral movements, the cutter elements at gage impact and engage the borehole sidewall, resulting in some lateral cutting into the borehole sidewall. The lateral cutting into the borehole sidewall may increase the diameter of the borehole and potentially cause the drill bit to deviate from its drilling path and initiate damaging vibrations such as bit whirl.
Accordingly, there remains a need in the art for a drill bit including depth-of-cut limiting features and that selectively control the aggressiveness of the bit in specific regions of the bit. Such drill bits would be particularly well received if they did not substantially decrease bit ROP.